Pressure swing adsorption (PSA) provides an efficient and economical means for separating a multi-component gas stream containing at least two gases having different adsorption characteristics. The more strongly adsorbable gas can be an impurity which is removed from the less strongly adsorbable gas which is taken off as product; or, the more strongly adsorbable gas can be the desired product, which is separated from the less strongly adsorbable gas. For example, in the latter case it may be desired to reduce the concentration of nitrogen and other inert materials in a natural gas stream, comprising methane, ethane, nitrogen, carbon dioxide and C.sub.3 +hydrocarbons, to improve the heat content of the product gas. This reduction of inerts is often requried to meet the quality specifications of pipeline companies who transport natural gas from a well head or natural gas processing plant to the consumer. Typically the natural gas must meet the following specifications:
______________________________________ Heat Content 900 to 1000 BTU Total Inerts (N.sub.2 + CO.sub.2) 7% maximum Nitrogen 3% maximum ______________________________________
Actual pipeline specifications vary somewhat depending upon the producer's contract for price and quality. In general, a specification for a higher heating value requires a lower amount of inerts such as nitrogen and carbon dioxide. Typically, natural gas at the well head can contain between 3 and 60 mol. % nitrogen, between 0.1 and 10 mol. % ethane, between 0.1 and 20 mol. % C.sub.3 + hydrocarbons and between 0.1 and 20 mol. % CO.sub.2. Inerts of which nitrogen is typically the major component, must be removed from natural gas to improve the heat content of the gas and to meet pipeline specification.
In pressure swing adsorption, a multi component gas is typically fed to at least one of a plurality of adsorption zones at an elevated pressure effective to adsorb at least one component, while at least one other component passes through. At a defined time, the passage of the feedstream to the adsorber is terminated and the adsorption zone is depressurized by one or more cocurrent depressurization steps wherein pressure is reduced to a defined level which permits the separated, less strongly adsorbed component or components remaining in the adsorption zone to be drawn off without significant concentration of the more strongly adsorbed components. Then, the adsorption zone is depressurized by a countercurrent depressurization step wherein the pressure on the adsorption zone is further reduced by withdrawing desorbed gas countercurrently to the direction of feedstream. Finally, the adsorption zone is purged and repressurized. The final stage of repressurization is typically with product gas and is often referred to as product repressurization.
In multi-zone systems there are typically additional steps, and those noted above may be done in stages. U.S. Pat. Nos. 3,176,444 issued to Kiyonaga, 3,986,849 issued to Fuderer et al., and 3,430,418 and 3,703,068 both issued to Wagner, among others, describe multi-zone, adiabatic pressure swing adsorption systems employing both cocurrent and countercurrent depressurization, and the disclosures of these patents are incorporated herein by reference in their entireties.
Various classes of adsorbents are known to be suitable for use in PSA systems, the selection of which is dependent upon the feedstream components and other factors generally known to those skilled in the art. In general, suitable adsorbents include molecular sieves, silica gel, activated carbon and activated alumina. The preferred adsorbent for a typical operation of the invention is activated carbon.
The applications for this technology are mostly in small natural gas plants of capacity of from 1 to 30 MMSCF/D. In these natural gas plants there are generally two product streams: natural gas liquids and compressed natural gas. The compressed natural gas comprising methane is returned to a pipeline and sold commercially.
In a typical natural gas plant wherein liquid hydrocarbons are recovered from the natural gas, the scheme consists of an inlet separator, a refrigerated flash zone, inlet gas and a stabilizer and recovery section. The inlet gas passes through an inlet separator and is cross-exchanged with the cold gas coming out of the system to reduce the temperature of the inlet gas. The cold gas is passed to a gas chiller wherein the gas reaches its minimum temperature. This minimum temperature generally ranges from 15.degree. F. to -40.degree. F. From the chiller the gas is passed to a cold separator to recover the sales gas and liquids. The liquids are recycled through a stabilization column wherein light material is removed to maintain a vapor pressure specifications. The overhead from the stabilization column is combined with the sale gas which is recompressed to pipeline pressures and returned to the pipeline. This sales gas is the feed to be processed in the instant process.
In a typical refrigeration system, the liquid product recovered comprises a portion of the C.sub.4 and heavier materials that are in the gas. Other light components, such as ethane and propane are not removed from the sales gas in this type of plant.
A second typical configuration for natural gas plants uses a turbo expander to reach cryogenic conditions for the recovery of the liquids from the natural gas. The inlet gas enters through an inlet separator and is cross-exchanged with the cold sales gas leaving the system. In this step, the temperature of the inlet gas is reduced to about -45.degree. F. The cold gas is passed through a turbo expander where it undergoes an isentropic expansion wherein it provides some energy recovery in a turbine. This expansion step reduces the temperature of the inlet gas to about -135.degree. F., depending on the operation of the system. The chilled gas is passed to a stabilization column and a liquids recovery system. In a plant with a turbo expander the recovery of ethane is significantly improved resulting in a sales gas which contains less than 1% of ethane and heavier hydrocarbons. The sales gas still contains a significant portion of inerts that have been carried through the system. Treatment of the sales gas to remove the inerts is often required to meet pipelines specifications before the sales gas is returned to the pipeline.
Another option for removing inert material from natural gas is to treat the raw natural gas at the wellhead before it reaches the pipeline or the natural gas plant. In some cases where the plant handles 15 MMSCFD comprising feed from 20 to 30 different wells, only some of the gas may contain significant amounts of nitrogen. Rather than construct a single large unit to remove nitrogen in the natural gas plant, it may be more economical to provide a smaller treatment facility to remove inerts from those particular wells where the inert concentration is highest. If the particular wells with the greatest amount of nitrogen amount to 25 to 40% of the total feed, this approach can result in significant operation cost savings by reducing the volume of gas required to be recompressed following the inert removal process.
The pressure history of the natural gas from the well head can provide a number of opportunities for the placement of this technology for maximum economic benefit. The movement of natural gas to the gas plant is accomplished by the compression at the well head to a pressure of 100-200 psia in order to gather the gas and send the gas to the natural gas plant. If the natural gas could be provided at a pressure of at least 100 psia, there would be sufficient pressure differential to operate the nitrogen removal process of this invention. More typically, the entire feed gas is supplied at a pressure range of from 220-250 psia, but this pressure is often reduced to 150 psia before it reaches the nitrogen removal process at the natural gas plant. Thus, if the gas could be treated before it reaches the natural gas plant at a lower pressure, there could be additional compression savings.
There are two approaches available in using a PSA process for the removal of nitrogen from natural gas. One approach employs a rate selective separation wherein the process takes advantage of the smaller kinetic diameter of nitrogen compared to methane to selectively adsorb the nitrogen into a molecular sieve, particularly a carbon molecular sieve. A number of U.S. patents (U.S. Pat. Nos. 4,578,089 and 4,376,640) claim the use of this approach for natural gas and air separation. The process of the current invention uses an equilibrium selective separation wherein methane adsorption is favored over nitrogen.